During and after the drilling of a well bore, tubular members are lowered into or raised out of the well bore. In one exemplary case, the tubular member is a casing string, which is usually a tubular steel pipe which serves to line the well bore and therefore to isolate the rock formations surrounding the well bore from the fluids passing along the well bore. The process of lowering the casing string into a well bore is usually known as running the casing string.
A casing string (or other tubular member within a well bore) generally consists of multiple sections or ‘joints’ of a standardized length, typically 12 meters (40 feet). The process of moving the casing string therefore proceeds in a number of repeated cycles, each cycle comprising adding or removing a joint to/from the upper end of the existing casing string and then moving the casing string within the well bore such that the process can be repeated. This process will be described, as part of an embodiment, in more detail below with reference to FIGS. 2a to 2d. 
While the casing string is being moved, it is attached to a moveable unit, typically referred to as a ‘hook’. The hook can be raised and lowered by a rig so as to move the casing string within the well bore. The hook, or equipment attached thereto, is capable of measuring the ‘hook load’, which is the total force on the hook. This force is dependent on the weight of the casing string (including collars and other ancillary equipment), accounting for any forces on the casing string caused by, for example, friction between the casing string and the well bore wall, buoyant forces on the casing string caused by its immersion in fluids, viscous drag caused by displaced fluid, and any pressure in the wellbore acting on the cross-sectional area of the casing string.
Traditionally, the hook load is measured so as to track the progress of the running of the casing string. One measurement of hook load is taken for each lowering cycle. This measurement is typically a steady state measurement performed ‘by eye’; that is, a human operator on the rig looks for a steady state in the hook load during the lowering of the casing string and records this as the hook load for that cycle. As the operator looks for a steady state during the lowering of the casing string, this measure of hook load may be used to calculate a measure of the dynamic friction (also known as kinetic friction) present between the casing string and the well bore. The measured hook-load value may be known in the art as the tripping-in weight.
A casing string (or other tubular member), being moved within a well bore may become stuck such that it can no longer be moved (either rotated or moved axially, up or down). Such situations, often known as ‘stuck casing’ or ‘stuck pipe’, are generally caused by excessive static friction along the well bore. One particular cause of a ‘stuck pipe’ is “differential sticking”, which is a situation where a tubular member is pressed against the side of a well bore so that it contacts the side of the well bore along a substantial length of the tubular member; however other causes of a stuck pipe are well bore collapse or some form of instability in the well bore.
A stuck pipe is one of the greatest problems involved with drilling a well bore, and can result in many days of lost productivity, result in losses to equipment (because the casing string or other tubular member cannot be recovered), and can reduce the output of a resultant well (due to narrower bore tubing having to be run down the stuck tubing).
As is known, static friction is the measure of friction between two surfaces that are stationary with relation to one another. By contrast, dynamic friction is a measure of the friction between two surfaces which are moving relative to each other. The causes of static and dynamic friction within a well bore are different, and consequently, the magnitudes of the friction forces in each case are different, with static friction generally being the greater.
Therefore, it has been found that the measures of hook load, and therefore measures of dynamic friction as described above, are unable to identify the magnitude or nature of static friction in a well bore.
It is an object of the embodiments to identify the magnitude and nature of friction between the well bore and a tubular member within it, and consequently to enable a more effective forecasting of a stuck tubular member (stuck pipe), as well as facilitating the diagnosis of well bore conditions which might lead to a stuck tubular member.
A further problem which may occur when moving a member in a well bore, either to run-in or pull out the member, is that the movement of the member causes a downhole pressure wave. This pressure wave may cause damage to the formation, and may cause fluid to leak out of or be drawn into the formation. Therefore a further object of embodiments is to enable the effects of the movement of fluid downhole to be detected.